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eni Ss.p.aA. upstream & technical services
2014-2015 Master in Petroleum Engineering and Operations
Well Testing for Reservoir Management: A Case Study
Author: Pratik Nityanand Rao
San Donato Milanese 15 October 2015
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Well Testing for Reservoir Management:
A Case Study
San Donato Milanese 15 October 2015
Author
Pratik Nityanand Rao
Division eni S.p.A.
Upstream & Technical Services
Dept. RESM
Company Tutors
Enzo Beretta
Giuseppe Tripaldi
University Tutor
Prof. Francesca Verga
Master in Petroleum Engineering & Operations 2014-2015
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Project Background
Discussion of the Case Study
Conclusions
List of Contents
Well Testing for Reservoir Management:
A Case Study
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Project Scope
To verify when the well testing interpretation of permanent
gauges is feasible and helpful for reservoir monitoring.
To provide a preliminary field characterisation for the case study.
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Considered Points
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Interference from nearby wells
Inadequate build-up and drawdown durations
Complex model
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Interference from Nearby Wells
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Drawdown Build-Up
Drawdown interpretation is usually
more reliable because each well
defends its drainage area
Build-up late time models are
usually disturbed by interference
from nearby wells
Shut-in well
Open well
Drainage area defended
Drainage area encroached
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Build-Up and Drawdown Durations: Standard Approach
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IARF (before reaching
boundaries)
Drawdown
(slope = 1)
Build-up
(reservoir
pressure
stabilises)
Sealing Barrier
Duration of radial flow is a function
of well location inside the reservoir
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Build-Up and Drawdown Durations: Alternative Approach
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IARF (before reaching
boundaries)
Sealing Barrier
Duration of radial flow is a function
of well location inside the reservoir
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Alternative Approach Workflow C
on
str
ain
t
Start!
Using log-log plot, match early and middle time models.
Set Initial Reservoir Pressure (from WFT/RFT).
STEP
2
Run sensitivities on boundary distances to match the pressure history.
STEP
1
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Complex Model
Analytical models are inadequate for matching in a single step
Step 1: Early + Middle time for estimation of wellbore and bulk reservoir properties.
Step 2: Middle + Late time for estimation of boundary distances.
Note: The two sub-models have to be consistent with the reservoir outer permeability because it is present in the middle time model, which is used in both steps 1 and 2.
Late Middle Early
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List of Contents
Well Testing for Reservoir Management:
A Case Study
Project Background
Discussion of the Case Study
Conclusions
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Well A Data
Gauge depth 2752 m TVDSS
Well Type Horizontal
Horiz. Net Length 200 m
Completion 7” – 5 ½”; Gravel Pack
General Information of the Field
A
B
2.7 km
Well B Data
Gauge depth 2753 m TVDSS
Well Type Horizontal
Horiz. Net Length 130 m
Completion 7” – 5 ½”; Gravel Pack
Reservoir & Fluid Data
Initial Reservoir
Pressure
372.9 bar
@ Gauge Depth
Lithotype Sandstone
Net pay 14 m
Porosity 23%
Fluid Type Wet Gas
CGR
15 bbl/MMscf
(0.000087)
STm3/Sm3
Specific
Gas Gravity 0.69
Gas FVF 0.0036 Rm3/m3
Gas Viscosity 0.029 cP
Total
Compressibility 1E-4 bar-1
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Production History (1/2)
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Field Production for Well A Alternating Production
for Wells A & B
Field
Rate
Well A BHP Well B BHP
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Production History (2/2)
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Field
Rate
Well A BHP
Well B BHP
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Build-Ups Comparison for Well A
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Build-up from 05/10/2012 (~103 days) Build-up from 19/01/2013 (~39 days) Build-up from 09/03/2013 (~220 days)
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Horner Match
Log-Log Match
Pressure History Match
Interpretation Model
Step 1: Well A Radial Composite Match
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Early Time: Wellbore Storage & Skin
Middle Time: Radial Composite
Late Time: Infinite Lateral Extent
Analysed
build-up
period
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Well A Radial Composite Output
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Inner Flow Capacity 2750 mD.m
Inner Permeability 200 mD
Outer Flow Capacity 560 mD.m
Outer Permeability 40 mD
Well Skin* -3.60
Total Skin -7.20
Interface Radius 350 m
Storativity Ratio 1
Mobility Ratio 5
Investigation Radius 3260 m
(*) The skin cannot be sub-divided into its components
(mechanical, geometrical and turbulence) because at
the horizontal well, the early time cannot be recognised
on the derivative plot.
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Horner Match
Log-Log Match
Pressure History Match
Interpretation Model
Step 2: Well A Closed System Match
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Early Time: Wellbore Storage & Skin
Middle Time: Homogeneous (outer kh)
Late Time: Closed Rectangle
Analysed
build-up
period
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Well A Closed System Output
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Gauge Depth 2752 m TVDSS
Initial Reservoir Pressure 372.9 bar
Initial Fluid Regime 1.36 bar/10m
Average Reservoir Pressure 348 bar
Average Fluid Regime 1.27 bar/10m
Depletion 25 bar
Distance (+x) 860 m
Distance (+y) 2300 m
Distance (-x) 1300 m
Distance (-y) 5750 m
Area 17.40 km2
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Well A Closed System Validation
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Reservoir Area = 17.40 km2
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Preliminary Estimate of the GOIP
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Gas Originally In Place (GOIP) = 14.40 GSm3
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GOIP from Geologist’s Method
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Area = 17.40 km2 = 17,400,000 m
Net Pay = 14 m (Net-to-gross ratio already factored in)
Porosity (f) = 0.23
Irreducible Water Saturation (Swi) = 0.1
Gas Formation Volume Factor (FVF) = 0.0036 Rm3 / m3
Gas Originally In Place (GOIP) = 14.00 GSm3
Area * Net Pay * f * (1- Swi) GOIP = ---------------------------------------------- FVF
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List of Contents
Well Testing for Reservoir Management:
A Case Study
Project Background
Discussion of the Case Study
Conclusions
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Conclusions (1/2)
CONSIDERED POINTS
SOLUTIONS APPLICATION ON THE CASE STUDY
Interference from nearby wells
To exploit long drawdown acquisition (at constant rate)
Well testing interpretation was performed on data that was unaffected by interference
Inadequate build-up and drawdown durations
Alternative workflow based on pressure matching needs: Reliable initial pressure from WFT/RFT At least one build-up acquisition
Applied
Complex model 1. Divide in sub-models 2. Numerical well
testing software Option 1 applied
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Conclusions (2/2)
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The standard approach for build-up and drawdown interpretation
cannot be applied to this case study
The reservoir pressure at gauge depth (2752 m TVDss) after 0.6
GSm3 of cumulative production resulted to be 348 bar, with a
corresponding depletion of about 25 bar
The average effective gas permeability for Well A was 40 mD
The skin was about -4, which indicates that the well is not damaged
The skin cannot be sub-divided into its components (mechanical,
geometric and turbulence) because at the horizontal well, early time
cannot be recognised on the derivative plot
The preliminary estimate of GOIP was 14.40 GSm3 (after cumulative
production of 0.6 GSm3)
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Acknowledgements
I would like to thank the Management of Eni
Upstream and Technical Services for permission to
present this work & related results, and RESM
colleagues for the technical support & needed
assistance.
San Donato Milanese 15 October 2015